BILL ANALYSIS 1
1
SENATE ENERGY, UTILITIES AND COMMUNICATIONS COMMITTEE
MARTHA M. ESCUTIA, CHAIRWOMAN
SB 107 - Simitian Hearing Date:
April 26, 2005 S
As Amended: April 19, 2005 FISCAL B
1
0
7
DESCRIPTION
Existing law:
1.Requires the California Public Utilities Commission (CPUC) to
reserve a portion of future electrical generating capacity for
renewable resources.
(Public Utilities Code Section 701.3)
2.Expresses legislative intent to increase renewable electricity
to 17 percent of consumption in the state by 2006.
(SB 1038 (Sher), Chapter 515, Statutes of 2002)
3.Requires each investor-owned utility (IOU) to increase its
existing level of renewable resources by one percent of sales
per year until renewable resources account for 20 percent of
its generation portfolio, provided sufficient Public Goods
Charge (PGC) funds are available to cover any above-market
costs.
(AB 57 (Wright), Chapter 835, Statutes of 2002)
4.The "Renewables Portfolio Standard" (RPS), requires IOUs and
certain other retail sellers to meet essentially the same
renewable procurement goals as AB 57, but sets a deadline of
2017 for achieving a 20 percent renewable portfolio and
establishes a detailed process and standards for renewable
procurement.
a. IOUs and other retail sellers must buy renewable
electricity from eligible resources to meet their RPS
obligations. Buying unbundled "renewable energy credits"
(RECs), rather than electricity, won't satisfy RPS
obligations.
b. To be eligible, renewable resources must be located in
or delivered to California. Delivery to a retail seller or
the Independent System Operator is required, but there is
no explicit requirement for delivery to the purchasing
retail seller.
c. Local publicly-owned electric utilities are not subject
to the same detailed process and standards as IOUs, but are
required to implement and enforce their own RPS programs.
(SB 1078 (Sher), Chapter 516, Statutes of 2002)
This bill:
1. Advances the deadline for achieving a 20 percent RPS
from 2017 to 2010 and requires the CEC to review the
feasibility of increasing the RPS target to 33 percent by
2020.
2. Authorizes IOUs and other retail sellers to buy RECs
instead of renewable electricity pursuant to a REC trading
program which allows the sale of the renewable attribute of
renewable electricity as a commodity unbundled from the
physical production and delivery of renewable electricity,
subject to the following conditions:
a. RECs may only be counted once (by the retail
seller who purchases the REC).
b. Any revenues received by an IOU for the sale of
excess RECs must be credited to ratepayers.
c. The quantity of RECs that can be separately
procured (as opposed to buying renewable electricity)
to meet a retail seller's RPS obligations may be
limited by the CPUC.
d. Renewable energy resources included in an IOU's
RPS baseline as of January 1, 2004 can't be sold off as
RECs.
e. RECs must originate from electricity generated
by an eligible resource and delivered in state.
f. RECs must include all environmental attributes
associated with production from an eligible resource,
except emission reduction credits (offsets) issued by
an air district.
g. A system for tracking and verifying RECs must be
established by the California Energy Commission (CEC)
before RECs may be used for RPS compliance.
h. An IOU may purchase RECs pursuant to a 10-year
contract only if the underlying electricity is sold in
California and it is not feasible or cost-effective to
deliver to the IOU's service territory.
1. Requires each local publicly-owned electric utility to
report to the CEC:
a. PGC expenditures for renewable energy resource
development.
b. Amounts of each type of renewable energy resource in
its portfolio.
c. Status of RPS implementation and progress toward RPS
goal.
1. Prohibits the CEC from recognizing RECs from a
pre-January 1, 2005 contract unless the contract specifies
ownership of the RECs. Prohibits the CEC from recognizing
RECs from a post-January 1, 2005 contract entered pursuant
to the Public Utility Regulatory Policies Act (i.e. a
Qualifying Facility contract).
2. Repeals the 20 percent cap for retail sellers, implying
the CPUC may require a retail seller to continue buying
renewable resources at the rate of one percent per year
after the retail seller attains 20 percent.
3. Authorizes recovery from ratepayers of an IOU's
"indirect costs" associated with buying renewable
resources, such as having to sell excess energy, decrease
output from lower cost resources or upgrade transmission
lines.
4. Provides an IOU may only receive an award of "new
renewable" PGC funds for a project if the project is
selected pursuant to a competitive solicitation the CPUC
finds complies with the RPS and the CPUC has approved a
contract for the project. These "supplemental energy
payments" may not be awarded for the purchase of RECs.
5. Repeals the requirement that the CEC direct 10 percent
($13.5 million/year) of renewable funds collected via the
PGC for credits to existing renewable direct access
customers (the CEC has suspended the customer credit
program and redirected the funds to other renewable
programs).
6. Permits an IOU serving fewer than 60,000 customers in
California that also serves customers in another state
(i.e. PacifiCorp and Sierra Pacific Power) to count its
out-of-state renewable resources toward its RPS compliance.
7. Requires IOUs and municipal utilities to adopt
strategies to achieve efficiency in the use of fossil fuels
and to address carbon emissions.
8. Requires the CEC to prepare recommendations for how to
"incentivize" municipal utilities to implement and enforce
RPS programs according to the standards applicable to IOUs.
9. Repeals several obsolete provisions and makes various
other technical and clarifying changes.
BACKGROUND
The RPS requires IOUs and certain other retail energy providers,
collectively referred to as "retail sellers," to buy renewable
electricity to the extent PGC funds are available to pay for any
costs exceeding a market price set by the CPUC.
Each IOU is required to increase its renewable procurement each
year by at least one percent of total sales, so that 20 percent
of its sales are renewable energy sources<1> by December 31,
2017. Once a 20 percent portfolio is achieved, no further
increase is required. The CPUC is required to adopt comparable
requirements for direct access energy service providers (ESPs)
and community choice aggregators (CCAs).
The RPS applies to:
1.IOUs meeting specified creditworthiness conditions.
2.ESPs, for any new customers or new contracts, and for all
customers beginning January 1, 2006.
3.CCAs.
---------------------------
<1> Eligible renewable technologies are biomass, solar thermal,
photovoltaic, wind, geothermal, renewable fuel cells,
hydroelectric 30 megawatts or less, digester gas, municipal
solid waste conversion, landfill gas, ocean wave, ocean thermal,
and tidal current. Existing small hydroelectric, existing
geothermal, and a garbage burning plant in Modesto may be
counted toward a retail seller's baseline, but are not eligible
for supplemental payments from PGC funds.
The RPS does not apply to:
1.Co-generation supplying customers on-site and via "over the
fence" transactions.
2.The California Department of Water Resources.
3.Municipal and other local publicly-owned electric utilities.
These utilities are responsible for implementing and enforcing
their own RPS programs.
The RPS requires the CPUC to adopt processes for determining
market prices, ranking renewable bids according to cost and fit,
flexible compliance rules and standard contract terms. The RPS
requires IOUs to offer contracts of at least 10 years, unless
the CPUC approves shorter contracts. This is intended to
support the development of new renewable resources.
The "Energy Action Plan" adopted by the CPUC, the CEC and the
California Power Authority pledges that the agencies will
accelerate RPS implementation to meet the 20 percent goal by
2010, instead of 2017. In his statements on energy, the
Governor has endorsed "20 percent by 2010" and proposed an
additional goal of 33 percent by 2020.
COMMENTS
1. D?j? vu. This bill is similar to SB 1478 (Sher), vetoed
by the Governor last year.
As approved by this committee last year, SB 1478 permitted
REC trading for RPS compliance, but allowed only one trade.
The only transaction permitted was sale of the REC by the
generator producing it to the retail seller using it for
RPS compliance. In effect, this provision prevented resale
by retail sellers and a secondary trading market for RECs.
The "one trade" condition was removed from SB 1478 in the
Assembly and replaced with a provision that allowed two
trades - the initial "bundled" sale of energy and a
subsequent trade. Even then, SB 1478 was vetoed on grounds
including that its remaining REC conditions were "onerous"
and it didn't open up the RPS to the entire western region.
This bill contains neither the one trade condition nor the
two trade condition. This bill does not limit the number
of REC trades and allows anyone, not just generators and
retail sellers, to trade RECs.
2. Will REC trading further the purpose of the RPS? Past
examples of environmental compliance via credit trading
programs indicate these programs provide a more convenient
way for regulated industry to achieve minimum compliance,
but don't necessarily promote investments to improve the
environment or effectively mitigate adverse environmental
impacts.
In this case, allowing retail sellers to purchase RECs
rather than the bundled renewable electricity product will
allow them more flexibility to comply with the RPS. For
example, an IOU with inadequate transmission to deliver
sufficient renewable electricity to its load can buy
conventional electricity from a local source to serve its
load and buy RECs originating from a distant renewable
producer to satisfy its RPS obligations. Or, a small
retail seller, such as an ESP, who may not be able to sign
the long-term contracts necessary to develop new renewable
resources, can buy RECs instead.
While REC trading may make RPS compliance more convenient,
it adds considerable complexity to a policy already bogged
down in complex implementation details. It also seems
inherently inconsistent with the goal of supporting the
development of new renewable resources within California.
This bill attempts to overcome this inconsistency by
imposing a variety of conditions on RECs.
This bill establishes a limited definition of RECs and
further limits how RECs can be traded in an effort to
prevent a wide-open REC market. However, the current RPS
requires retail sellers to purchase the renewable
electricity itself, and contemplates IOUs will comply by
buying renewable resources via long-term contracts with
in-state producers, rather than by buying RECs.
The author and the committee may wish to consider whether
REC trading is consistent with the goals of the RPS and
whether it should be permitted for RPS compliance. If the
intent is to authorize RECs as a compliance alternative,
the author and the committee may wish to consider the
following additional specific limitations on their use in
the RPS:
a. Permit only one trade of a REC unbundled from
renewable electricity.
b. Permit only renewable producers and retail
sellers to trade RECs.
1. Is there any evidence that REC trading is needed?
Proponents of REC trading say it is needed to address
either their inability to deliver renewable electricity to
their customers or their inability to enter the long-term
contracts for renewable electricity contemplated by current
RPS law.
Sempra wants RECs because it says it doesn't have enough
renewable electricity potential within San Diego or
deliverable to San Diego using existing transmission lines.
So, instead of investing directly in renewable generation
itself, it wants to be able to purchase RECs from renewable
generation that someone else has invested in. While
Sempra's deliverability issue is legitimate, it doesn't
require REC trading to solve. It can be addressed through
exchanges with other California utilities, while retaining
the new investment focus of the RPS. This approach may
require a fairly minor clarification of delivery
requirements in current law.
ESPs want RECs because entering long-term contracts to
support development of new renewable resources doesn't fit
their business model - which is to buy electricity
sufficient to serve their customers on a relatively
short-term basis.
Sempra and the ESPs are pointing to prospective problems
which have not been confronted in RPS implementation to
date. Nor have they demonstrated that REC trading is
needed to address them. The author and the committee may
wish to consider whether REC proponents should show
evidence of need prior to permitting REC trading, rather
than permitting it based on speculation about prospective
problems.
2. 20 percent by 2010, then what? One percent per year is
the current rate of renewable additions required by AB 57
and the RPS. This pace leads all IOUs to reach 20 percent
on or before 2017. Because Southern California Edison is
already near 20 percent, advancing the deadline to 2010 may
not have a material impact on its RPS obligations. Pacific
Gas & Electric reports a 2004 baseline of 12.7 percent, so
would need to increase to about 1.2 percent per year to
reach 20 percent by 2010. San Diego Gas & Electric is
currently at about 7 percent, so would need to increase to
about 2.2 percent per year to reach 20 percent by 2010.
In addition to advancing the 20 percent deadline to 2010,
this bill removes the 20 percent cap for retail sellers,
implying the CPUC may require an IOU or another retail
seller to continue buying renewable resources at the rate
of one percent per year after attainment of the 20 percent
goal. The bill also requires the CEC to review the
feasibility of increasing the RPS target to 33 percent by
2020 and report back to the Legislature.
3. Who gets to count RECs from PURPA contracts? In 2003,
the Federal Energy Regulatory Commission (FERC) ruled that
long-term PURPA contracts with Qualifying Facilities do not
necessarily result in the conveyance of RECs to the
purchasing utility. FERC reasoned that its "avoided cost
regulations did not contemplate the existence of RECs and
that the avoided cost rates for capacity and energy sold
under contracts entered into pursuant to PURPA do not
convey the RECs, in the absence of an express contractual
provision."
FERC left determinations regarding ownership to the states,
noting that "states, in creating RECs, have the power to
determine who owns the REC in the initial instance, and how
they may be sold or traded; it is not an issue controlled
by PURPA."
This bill addresses the REC ownership issue teed up by FERC
for the states by not permitting the recognition of RECs
from PURPA contracts (unless an existing contract specifies
ownership of the RECs) and therefore preventing the
scenario where RECs would be created and sold apart from
the contract, which could result in double payment for the
same renewable electricity or disqualification of PURPA
contracts now counted toward IOUs' RPS baselines. The
provisions in this bill assure renewable power from PURPA
contracts count toward the RPS obligations of the
purchasing IOU and are similar to provisions in SB 431
(Battin), approved by this committee April 19.
4. Should ratepayers pay for RPS excesses? This bill
authorizes recovery from ratepayers of an IOU's "indirect
costs" associated with buying renewable resources, such as
having to sell excess energy, decrease output from lower
cost resources or upgrade transmission lines. As written,
this seems like a fairly open-ended and unbalanced
obligation on ratepayers. The author and the committee may
wish to consider specifying that such indirect costs, in
order to be recovered, must be prudently incurred,
necessary to comply with the RPS and in ratepayers'
interest.
In addition, the author and the committee may wish to
consider whether such expenses, if they are unique to
buying renewable resources, should be funded out of the
PGC.
5. CEC reports should be consolidated. The author and the
committee may wish consider combining the two CEC reports
required by this bill and incorporating them into the CEC's
current Integrated Energy Policy Report process.
6. Technical amendments. This bill requires a variety of
technical and clarifying amendments to ensure consistent
standards, terms, cross references and grammar.
7. Related legislation. Two competing measures based on SB
1478 were introduced in the Assembly, AB 1362 (Levine) and
AB 1585 (Blakeslee). AB 1362 appears to permit unlimited
REC trading for RPS compliance. As introduced, AB 1585
permitted unlimited REC trading, but was recently amended
to remove all provisions except a CEC study of the
feasibility of attaining a 33 percent RPS standard. Both
bills are set for hearing in the Assembly Natural Resources
Committee April 25.
POSITIONS
Sponsor:
Author
Support:
Clean Power Campaign
East Bay Municipal Utility District
Independent Energy Producers (if amended)
Sierra Club California
The Utility Reform Network
Union of Concerned Scientists
Oppose:
California Council for Environmental and Economic Balance
Calpine
Constellation New Energy
Pacific Gas and Electric Company
Sempra Energy
Southern California Edison
Lawrence Lingbloom
SB 107 Analysis
Hearing Date: April 26, 2005